It is well known in the art that corrosive elements and related contaminants are present in pipelines used for transporting sweet and sour hydrocarbon gases downstream of gas-oil separation plants. Corrosive contaminants are damaging to metal equipment, and more particularly to steel pipelines and fittings. Hydrocarbon pipelines cover substantial distances worldwide. Therefore, corrosion protection of these lines is of vital importance, especially in heavily populated and environmentally sensitive regions. Damage to pipelines by corrosive elements can result in catastrophic disasters culminating in losses of human life and substantial injury to the environment, in addition to extreme economic loss. Therefore, it is essential that the presence of corrosive elements in such pipelines be carefully monitored and neutralized by the addition of effective amounts of corrosion inhibitors.
Monitoring corrosion inhibitors transported over long distances in pressurized gas pipelines has proven to be a challenging task. Computer simulation program models have been developed and implemented to simulate and predict the transport properties of inhibitor compounds and solutions employed for treating and neutralizing corrosive elements across pipeline distances. Although these simulation programs have proved useful, analytical sampling is still necessary for verification of the presence of effective amounts of corrosion inhibitors and their derivatives. However, conventional sampling for analysis has also proved to be difficult in sour gas pipelines based on limited access to sampling points.
Various methods, techniques and chemicals have been developed for removing or minimizing the effects of corrosive substances in sour gas lines. As used herein, the term effective amount of corrosion inhibitor, such as imidazoline and/or its derivatives, is that amount necessary to eliminate or keep to an acceptable minimum corrosion of the pipeline and its fittings. Specific methods for removing water and sulfur-based compounds are disclosed in the art. For example, Nivens, et al. U.S. Pat. No. 4,011,882 discloses a method for minimizing sulfur contamination of refined hydrocarbon fluids transported in a pipeline for the transportation of sweet and sour hydrocarbon fluids by first mixing a corrosion inhibitor with a sour hydrocarbon and transporting the mixture through the a pipeline. The sour mixture is subsequently followed by a sweet hydrocarbon wash solution including amines. Finally, a refined hydrocarbon fluid is transported through the pipeline.
Roe U.S. Pat. No. 6,063,288 teaches a method for controlling the deposition of silicate and silica-containing scales in an aqueous system comprising the addition of an imidazoline or imidazoline derivative to control scale deposits on the surfaces contacted by the aqueous system. Roe is limited to the interaction of silicate and silica with imidazoline and imidazoline derivatives in industrial applications such as cooling and boiler water systems.
Knox et al. U.S. Pat. No. 4,927,669 discloses an inhibitor formulation including the product obtained by reacting maleic anhydride or fumaric acid with fatty acids containing unsaturation in the presence of a suitable catalyst, such as iodine, clay or silica. The disclosure in Knox purports to provide improved corrosion inhibition in oil field equipment and piping over conventional dimer/trimer based inhibitor formulations.
Alford et al. U.S. Pat. No. 5,174,913 discloses a corrosion inhibitor with improved film forming and film persistency characteristics produced by first reacting, in a condensation reaction, a polybasic acid with a polyalcohol to form a partial ester. Next, the partial ester is reacted with imidazoline and/or fatty diamines to salt the ester. Alford further teaches of reacting the slated ester with a metal hydroxide, a metal oxide, and/or ammonia to further salt the ester. In addition, surfactants may be added to tailor the inhibitor formulation to meet the specific needs of the user.
Poirier et al. U.S. Pat. No. 5,199,978 discloses a process for removing elemental sulfur from fluids such as gasoline, diesel fuel, jet fuel or octane enhancement additives such as ethers (MTBE) which pick up sulfur when transported through pipelines which are otherwise used for the transport of sour hydrocarbon streams. Sulfur containing fluids are mixed with an inorganic caustic material, an alkyl alcohol and an organic mercaptan or inorganic sulfide compound capable of reacting with sulfur to form a fluid insoluble polysulfide salt reaction product at ambient reaction temperatures. The treated fluid is then contacted with an adsorbent or filtered to remove the insoluble salt leaving a fluid product of very low residual sulfur content.
Fischer et al. U.S. Pat. No. 5,292,480 discloses a corrosion inhibitor with excellent film forming and film persistency characteristics. The corrosion inhibitor in Fischer is produced by first reacting unsaturated fatty acids with maleic anhydride or fumaric acid to produce the fatty acid Diels-Alder adduct or the fatty acid-one reaction product. The adduct or reaction product is further reacted in a condensation or hydrolysation reaction with a polyalcohol to form an acid-anhydride ester corrosion inhibitor. The ester may be reacted with amines, metal hydroxides, metal oxides, ammonia, and combinations thereof to neutralize the ester.
Gillespie et al. U.S. Pat. No. 5,389,240 discloses a method for removing naphthionic acids. Naphthionic acids may be removed from liquid hydrocarbon feedstocks by passing such feedstocks through a bed of certain metal oxide solid solutions related to hydrotalcites. The removal of naphthionic acids is an important adjunct to sweetening sour feedstocks and is particularly applicable to kerosines whose acid numbers may range as high as about 0.8.
Ferm et al. U.S. Pat. No. 5,401,390 discloses a catalyst and a process for using the catalyst disclosed. The catalyst is a metal chelate dispersed on a basic support which is a combination of a solid base and a secondary component. The solid base can be a solid solution of metal oxides and/or a layered double hydroxide (LDH) and the secondary component can be calcium oxide, magnesium oxide, calcium hydroxide and magnesium hydroxide. The process involves contacting a sour hydrocarbon fraction which contains mercaptans with the catalyst in the presence of an oxidizing agent and a polar compound.
Falkiner et al. U.S. Pat. No. 5,525,233 discloses a process for removing elemental sulfur from fluids such as refined petroleum products transported through pipelines normally used for the transport of sour hydrocarbon streams. The sulfur containing fluids are mixed with an immiscible aliphatic solution containing an inorganic caustic material, methanol or aqueous alcohol and an inorganic sulfide or hydrosulfide capable of reacting with the elemental sulfur in a mixing zone to form a polysulfide present in the immiscible alcoholic solution.
Fischer et al. U.S. Pat. No. 5,759,485 discloses water-soluble corrosion inhibiting compositions and the method of making the same. Specifically, this invention relates to inhibiting the corrosion of metals, particularly those employed in the production, processing, and transportation of petrochemical products. These water-soluble corrosion inhibiting compositions are created by neutralizing a tricarboxylic acid with aminoethylethanolamine and a member selected from the group consisting of imidazoline, amidoamine, and combinations thereof. The resulting compositions exhibit improved film persistency characteristics even when utilized in small amounts.
Kratz et al. U.S. Pat. No. 5,840,099 discloses a process for the selective removal of water, CO2, ethane and C3 hydrocarbons from gas streams, particularly a natural gas stream comprising primarily methane. The process comprises contacting the gas stream with an adsorbent material consisting exclusively of one or more compounds which are basic (i.e., compounds which, when contacted with a pH neutral aqueous solution, cause such solution to have a pH greater than 7.0) and which are mesoporous (i.e., compounds that have moderately small pores providing a surface area less than 500 m2/g). Typical mesoporous adsorbents which are disclosed include zinc oxide, magnesium oxide and, in particular, activated alumina.
As demonstrated by the above discussion, many corrosion inhibitors are known in the art, and their application to liquid hydrocarbons is broad-ranging. Generally, in diesel fuel, oil-soluble corrosion inhibitors are applied. Concentrations range from about 2% to as much as 20% by volume. The inhibitor is injected as a solution through an injection quill upstream of the region where corrosion protection is required.
Generally, corrosion inhibitors are injected in the hydrocarbon stream at gas-oil separation plants to prevent corrosion from wet fuel. The inhibitor is further transported with the diesel fuel downstream ideally in a regulated and predictable manner. However, because there always exists some uncertainty as to actual injection rates of the corrosion inhibitors and to make more effective use of chemical inhibitors, manual sampling is desirable. Manual sampling assures the operator that a measureable amount of inhibitor residue is available to neutralize the corrosive compounds transported with the gas. Therefore, in order to effectively apply the proper amount of corrosion inhibitor and to limit excess residue transported along the pipeline, an effective method and apparatus for sampling must be provided. Thus, while the prior art has long taught the use of corrosion inhibitors, it has not disclosed a method or apparatus for testing to determine the presence of an excess or residue of said corrosion inhibitor(s) found in the pipelines.
The level or concentration of corrosion inhibitors remaining in a sour gas contained in a high pressure pipeline is difficult to determine analytically. Specifically, existing apparatus and methods for sampling high-pressure gas streams make it difficult to capture and analyze for the presence of corrosion inhibitors. The detection of corrosion inhibitor residue is made difficult due to such factors as aromatics content, the length of the pipeline, pipeline temperature, batch size, batch sequencing, and the like. In addition, obtaining the required samples is difficult where liquid phase corrosion inhibitors accumulate in the lower half of the pipeline. However, existing gas sampling taps and valves are typically positioned in the upper portion of the pipeline, since it is preferred to place sampling valves in the upper portion in order to avoid contact with the highly corrosive liquids. Therefore, an effective sampling method is required that will provide for the recovery of representative samples for analytical testing.
Current sampling methods in the art employ analysis of condensate withdrawn from slugcatchers. Slugcatchers are an effective source of pipeline liquids; however, they fail to provide a representative sample throughout the length of the pipeline. Recovery of non-representative samples occur because slugcatchers are generally located at the terminal points of a pipeline. In addition, slugcatchers are sometimes common to more than one pipeline. Slugcatchers have not been utilized in the art and are not an acceptable source of samples for use in analyzing for residual corrosion inhibitors, specifically imidazoline-based inhibitors, in the feedstream of a gas transmission pipeline.
Another method of trapping corrosion inhibitor residues in volatile solvents has been employed with very limited success. Gas from the pipeline is bubbled through a solvent trap containing methylene chloride or chloroform at atmospheric pressure. One drawback of this method is that gas entering the solvent trap is less likely to be representative of the gas in the pipeline. For example, liquid residing in the body of the valve could be entrained by gas rushing past the valve orifice, or conversely, liquid entrained in the gas may not stay entrained while traveling through a long conduit from the valve to the solvent trap. There are many other difficulties associated with this method, including the handling and transportation of a volatile solvent and the regulation of gas flow through the pipeline gate valve, that render this method impractical, hazardous, and unreliable.
Analytical methods that are endorsed by the manufacturers of the chemical corrosion inhibitors tend to rely on the observation of fluorescence spectra, either directly from active amine, amide or imidazoline, or from the derivatives generated from the parent amine, amide and imidazoline complexes that exhibit strong fluorescence spectra. This approach does not reveal any specific structural information about the active ingredient. The protection of the proprietary formulations of their products may be why the chemical manufacturers endorse its practice. Thus, using fluorescence methods, it may be difficult, if not impossible to distinguish between different products. A more serious shortcoming is the potential for interference from residual condensate and/or oils that bear unsaturated functional groups, which can also contribute to fluorescence.
The determination of moisture content in gaseous process streams can be utilized to indicate important process conditions both upstream and downstream of the sampling point. In many chemical plants and petroleum refineries, the exact amount of water in a process stream determines the economic return on the process. For example, catalytic reformers in refineries should be operated with a very low water content for best results.
The aqueous dew point is an important parameter in the design and operation of natural gas production, processing and transportation facilities. Without on-line moisture monitors, accurate field measurements of the aqueous dew point in bases are notoriously difficult to obtain. Commercial moisture monitors are used for specific applications, but these monitors are in fixed locations to provide process information, such as the performance of a TEG dehydration plant.
Conductivity-type moisture monitors are in common use, but also have limitations. The probe cannot be exposed to conductive liquids and can be damaged by materials that are corrosive to aluminum or aluminum oxide. This includes strongly acidic materials such as hydrogen sulfide present in natural gas streams and the primary amines used as corrosion inhibitors.
Moisture analyzers for use in the laboratory are commercially available. However, these instruments require calibration, include complex electro-mechanical systems, and require gas flow measurement apparatus when used in the field. See, for example, U.S. Pat. No. 3,405,550 and it commercial embodiment from Lockwood and McLorie, Model 100.
In view of the foregoing, there clearly exists a need for an improved method and apparatus for the sampling and detection of surface-active agents in pressurized gas streams. There is also a need in the art to provide a simple, practical and effective method for monitoring and detecting the presence of residual corrosion inhibitor compounds and/or their derivatives in a gas pipeline sample.
Therefore, it is an object of the present invention to provide a method and related apparatus for sampling sour gas streams to detect the presence of surface-active additives in those streams.
Another object of the present invention to provide a method and apparatus for measuring corrosion inhibitor residue, and more specifically, imidazoline-based inhibitors, in a hydrocarbon gas stream moving through a pipeline.
It is a further object of the present invention to provide a safe and reliable method and apparatus for analyzing a gas stream to which has been added one or more corrosion inhibitors for protection of the pipeline and fittings.
Another object of the present invention to provide a method for the sampling of residual corrosion inhibitor, such as imidazoline and its derivatives, for the purpose of optimizing the injection rate of an effective amount of such costly corrosion inhibitors.
Yet another object of the present invention is to provide an apparatus for use in existing pipeline sampling systems without requiring expensive material alterations and the installation of new sampling fittings.
Other objects, features and characteristics of the present invention, as well as the methods of operation and functions of the related elements of the invention and the combination of parts and economies of development and performance, will become apparent upon consideration of the following detailed description with reference to the accompanying drawings, all of which form a part of this specification.